Webinar: CCS major project development lessons from the ZeroGen experience


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The ZeroGen Integrated Gasification Combined Cycle (IGCC) with CCS project, was a first-of-a-kind, commercial-scale CCS project proposal in Australia. Lessons learnt from this project include real-life project management experience integrating the key elements of a large-scale CCS project, from the technical to the commercial to stakeholder management.

This webinar was presented by Professor Andrew Garnett, Director, Centre for Coal Seam Gas, The University of Queensland. The Q&A session also included Martin Oettinger, Deputy Director, Low Emissions Technology for ACALET. Martin's career includes 6 years in a senior technical leadership role with ZeroGen.

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Webinar: CCS major project development lessons from the ZeroGen experience

  1. 1. CCS major project development lessons from the ZeroGen experience Webinar – 21 August 2014, 1700 AEST
  2. 2. Professor Andrew Garnett Director, Centre for Coal Seam Gas, The University of Queensland Professor Andrew Garnett is a newly appointed Professor and Director of the University of Queensland CCS Program in the UQ Energy Initiatives (he is also Director at the UQ Centre for Coal Seam Gas). A former Shell and Schlumberger executive, Andrew has over 25 years’ worldwide experience with oil majors in conventional and unconventional hydrocarbon exploration, appraisal and development projects. Prior to joining the University of Queensland, Andrew consulted widely on unconventional and acid gas developments, most notably those with high GHG emissions footprints, and worked on the 500MW, 60 MT ZeroGen IGCC & CCS Project, as manager for Carbon Transport and Storage and ultimately as CEO and Project Director.
  3. 3. Martin Oettinger Deputy Director, Low Emissions Technology, ACALET Martin Oettinger is Deputy Director, Low Emissions Technology for ACALET (Coal21 Fund), aimed at facilitating the early demonstration of low emissions black coal technologies. Prior to this he was Principal Manager – Carbon Capture, for the Global CCS Institute. Martin has over 30 years’ experience in senior technical, leadership and management roles for a range of blue-chip Australian and international corporations in the power, mineral and hydrocarbon processing industries. The last 15 years of his career have involved large-scale first-of-kind developments, including 6 years in a senior technical leadership role with ZeroGen.
  4. 4. QUESTIONS  We will collect questions during the presentation.  Your MC will pose these question to the presenter after the presentation.  Please submit your questions directly into the GoToWebinar control panel. The webinar will start shortly.
  5. 5. CCS Major Project Development Lessons from the ZeroGen Experience Confidential Prof. Andrew Garnett UQ Energy Initiative Director, CCS (former CEO & Project Director ZeroGen) Disclaimer: The views presented in this presentation do not necessarily represent the views of ZeroGen, its former directors, former funders or the University of Queensland.
  6. 6. Background & Context ► ZeroGen Pty Ltd was fully owned by the Queensland State Government and sponsored by Federal Government & the Australian Coal Association (ACALET). It was established to … ► “Facilitate the development and accelerated commercial deployment of low emissions coal technology to preserve Queensland’s competitive position in power generation and to ensure the continued mining use and exploration of Australian black coal”. ► Configuration ► IGCC with CCS ► 530 MW (gross) 391 MW (net) ► Capture ► 65% ~ 2 mln tpa ► 90% ~ 3 mln tpa 250MW plant at Nakoso constructed by MHI MHI Confidential
  7. 7. Location of Project Confidential Nth Bowen Basin Surat Basin Gladstone Brisbane ZeroGen Tenements Emerald Miles Roma
  8. 8. Evolving Scope 80MW IGCC 75% Capture + Pipeline 80MW Demo + Trucking 3.3 mln t 84 mln t ZG1 ZG2 ZG3,ZG4,ZG5,ZG6 ZG7,ZG8,ZG9,ZG10,ZG11,ZG12 2000 1500 1000 500 Confidential Design/Build Injection Skid Injection Test 0 ‘000 T CO2 PA 2006 2007 2008 2009 2010 2011 DP-1 9 mln t DP2b 120MW DP2a 3000 2500 Scope / MW Gasif. Power Solvent etc % capture 100/200 Noell GE/Siemens Selexol 90% 200 Shell GE 9E Selexol 75% 47 Shell GE 6B E Sulferox, Sulfinol 75% 87 Shell GE 6FA Genosorb-sulferox 75% 120 Shell GE 400 MHI MHI 701G2 Selexol 65-90% 60 mln t Clean Coal Council Approval of 530MW Plant Potential Rate to be Sequestered Tenements in Surat released Flagship 2015 Flagships Jun 10 PFS Report Jul 10 Alt basins studies
  9. 9. IGCC with CCS – PFS Configuration Coal handling, grinding and drying Confidential ASU Gasifier & Syngas Cooler Slag, Waste Water and Solids Handling CO Sour Shift CO+H2O -> CO2 + H2 Water Treatment Location - B Location - D Raw Water CO2 Compression & Dehydration Solexol AGR & CO2 Removal Wet Sulphuric Acid Plant Sulphuric Acid Handling & Export Syngas CCGT Power Block Substation Transmission Lines CO2 Pipeline (? Boosters) CO2 Storage Field Location - A Location - C Location - E composition, pressure(t)
  10. 10. And so … lessons ? Confidential
  11. 11. AGAIN ! Cost Estimate Growth vs. Engineering Effort • RAND corp study – (an alternative look-ahead view) 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 Duke Edwardsport 2006-2012 0 1 2 3 4 5 Ration of Estimate to Initial (class 0) estimate. Approx. Estimate Class • RAND corp study – 1981 (a look back view) Ratio of estimate to Final Cost Estimating Maturity completion ZeroGen Scoping to end PFS $4.3B $6.9B 1. % of capital cost in new technology compared with the capital cost of the entire plant, 2. complexity of the plant, - the number of continuously linked process units, 3. the degree of project definition, and 4. the degree of process definition.
  12. 12. Costs to end PFS Cost Group Estimated Cost (M AUD) % of Total COStorage Prior to PFS period (6 wells) $48.0 2 all configs. PFS period (6 wells) $53.6 73.5% Power Plant with Engineering $14.71 Capture 13.9% final config. only Coal Studies & Testing $2.43 Site Selection $1.87 Operations & Maintenance Studies $0.26 Environmental Studies $2.68 1.9% Stakeholder Engagement $0.81 0.6% Commercial Capital & Operating Cost Estimates $0.31 Studies Power Revenue & Trading $0.20 0.9% Financial Modelling $0.35 Financing Studies $0.40 Project Management & Controls $4.08 3.0% Corporate Administration, Financing Studies, etc $8.6 6.2% Total Study Expenditure $138.3
  13. 13. From end PFS – CtG … Capital Cost Estimates • Prefeasibility Study Estimated TIC of $6.93 billion, including escalation to 2016 start-up [cf $4.3 billion in scoping study- Oct 2008 Basis] Main Project Cost Area AUD billions % Total ZG Owner’s Costs $ 0.30 5% Enabling Works $ 0.62 11% Power Plant incl. Balance of Plant $ 3.90 68% Carbon Transport & Storage (scoping) $0.80 14% Operations Readiness & Start-up $0.14 2% Total Base Cost Estimate $5.76 100% Direct project contingency $ 0.52 9% Escalation $0.65 11% Total Fully Load Capital Cost $6.93
  14. 14. Reconciling the Cost Increases It’s about design maturity, Australian productivity and site specific issues [ $4.3 B AUD to $6.29 B AUD incl. contingency] May 2010 Basis Escalation 2016
  15. 15. Decision to discontinue In November 2010, ZeroGen management advised closure of the ZeroGen commercial scale IGCC with CCS demonstration project due to: • very high capital and operating costs which could not be supported by anticipated revenue streams; • technical risks around the CO2 capture technology and project integration; and • lack of credible project funding opportunities to achieve financial close. • inability of the Northern Denison Trough storage resource to accommodate the sustained injection rates or volumes of CO2 required by the project; • uncertainty as to the timely award of sufficient tenure and funding necessary to successfully appraise an alternative CO2 storage resource; • AND also advised that lessons be documented (an activity which was concurrent with project close-out, surrender of licenses and final members’ voluntary liquidation)
  16. 16. Key Lessons Learned - SUMMARY 1. Markets & Economics: Industrial–scale in Aust. is simply not economic or supportable 2. Scale: Industrial–scale is not a simple scale–up from demo. scale 3. Risk Mgmnt: Careful pace of ‘first’ projects is critical to wider deployment. 4. Risks Mgmnt : Pre–FEED and feasibility risks and costs are heavily weighted to the search for storage. 5. Risks Mgmnt : Storage is a natural resource, a portfolio exploration and appraisal approach is needed. 6. Clear Storage Goals: When defining storage resources requirements it is essential to discuss the consequences and trade–offs between injection rate and/or cumulative volume objectives. 7. FEL costs: Very high front–end engineering loading is needed for first–of–a– kind.
  17. 17. Key Lesson Learned ... #1 • Industrial–scale, low emissions coal–fired power projects incorporating CCS are not currently economic (in the Queensland, Australia context) – costs are well above published costs • While limited funds are potentially available from strategic investors such as the coal industry and technology providers, the project team for this FOAK project identified a large funding gap which could not be closed. • Deployment and operating costs for ZeroGen were at (beyond) the upper limit of published ranges. • FOAK low emissions coal–fired power projects that incorporate CCS have very high capital and operating costs and with forecast electricity and carbon prices, will generally not be financially viable. • Would require significantly heavier & more ongoing gov. financial support than previously thought. • Low emissions coal–fired power projects must rely on large capital and operating subsidies, the majority of which governments will be required to fund. • This is exacerbated in Australia, where strong levels of major resource project activity in the creates skills shortage adversely impacting labour cost and productivity.
  18. 18. Key Lesson Learned … #2 • Industrial–scale is not a simple scale–up from demonstration–scale • ZeroGen experience: for full comprehension CCS projects should be at commercial scale. • Only at this scale that significant reality checks can be made regarding schedule, cost and performance predictions • Only at this scale that the main locally–relevant deployment challenges emerge and can be understood. • Desk–top analyses proved inadequate. • For storage, a significant acquisition and evaluation (drilling, testing and seismic) program proved to be necessary and this should have been conducted well before significant power plant engineering commenced. • Such exploration and appraisal programs are, by their nature, subject to significant uncertainty as is the level of funds at risk. • The scale of funds available for such programs should be flexible and large enough to provide a portfolio chance of success in line with the risk tolerance of the funders.
  19. 19. Key Lesson Learned … #3 • Measured management of pace of ‘first’ projects is critical to wider deployment • First CCS projects carry the burden of ‘proof’ for follow–up wider deployment. • Risk management, approaches to Environmental Impact Assessments and public consultation will need to be conservative and with measured (slow) pace. • This requirement runs counter to any urgent push or mandate for an early operational start date (or to spend budget in any calendar year !). • ZeroGen experience suggests that, at least in the case of IGCC, CCS project schedules need to be risk optimised, such that larger investment decisions in plant and capture are not taken before achieving sufficient confidence that – storage is present ? – will perform as required ? – is licensable and acceptable ?
  20. 20. Risk Optimised Project Scheduling “pre-project” Confidential DG7 Appraisal of Selected Sites IR IR IR Screening DG1 DG5 Field Development Planning EIS & Approvals Develop Field Project Completion IR IR IR Feasibility & BED Construct Inject Operate Closure FEED IR CO2 TRANSPORT & CAPTURE CO2 STORAGE Exploration Scoping DG2 DG3 Prefeasibility IR DG4 Detailed Engineering DG6 IR DG8 FULLY INTEGRATED CCS DEVELOPMENT IR IR IR Note: the CO2 Transport and Capture Prefeasibility stage may also be delayed until after the Storage Appraisal of Selected Sites, depending on the residual post-Exploration risk and the estimated cost of the Prefeasibility Study.
  21. 21. Key Lesson Learned … #4 • Pre–FEED and feasibility costs, risks and uncertainties are heavily weighted to the search for storage • Prior to Front End Engineering Design (FEED) and probably prefeasibility stages for an integrated CCS project, the majority of at-risk expenditure lies in finding and appraising storage resources to a sufficient level of confidence (in storage security and sustained injectivity) to justify a larger investment in plant engineering. • In ZeroGen’s case: – over 70% of expenditure to end PFS was related to storage (and this was to ultimately establish the site was not appropriate) – 20% to plant and capture. • Forecasts to evaluate an entirely new storage area to a mature stage of characterization would have resulted in over 90% of costs, to the end of prefeasibility, being storage related. • Note especially that commonly available storage “Atlas” type estimates, based on pore-space corrected, volumetric estimates should give NO confidence that appropriate, rate matched storage is available.
  22. 22. Lessons: Storage pre-project works ? • Prior to site-specific characterisation storage uncertainties and risks are high. – Are there any storage resources that can perform as required ? – If so, then how much and are they developable ?. • Exploration plans must include a risk-diverse portfolio of prospects. – Risks should be diversified in geology, environmental, technical, overlapping-resources, community and public acceptance ... • BUT, without more drilling and dynamic testing we simply do not have a handle on how much practical storage there is. ZeroGen Northern Denison Trough QLD storage Atlas1 BWW “High Prospectivity” Basin (Bradshaw et al, 2009) 1 Bradshaw et al (2009) Confidential Desktop Studies static capacity in ZeroGen acreage. Results from ZeroGen Drilling, Testing & FDP Effective resource (technical FDP constraints only) Contingent capacity (limited only by FDP and project lifetime) Practical Capacity (unit cost, project and rate constrained) Aldebaran, Freitag & Cath. QLD Atlas 50 – 90 mln t Catherine ~ 10 mln t Aldebaran, Freitag & Cath. Zerogen 80 – 100 mln t Catherine was found to be main practical formation Catherine 20 – 30 mln t 54 mln t (takes 120 yrs to fill) 25 mln t (at >$140/t, CTS) ZERO tonnes
  23. 23. Key Lesson Learned … #5 • Storage is a natural resource, a portfolio exploration and appraisal approach is needed • Exploration and appraisal of potential storage sites requires a portfolio approach to create multiple options to allow for some sites which might be found to be ‘unsuitable’. • A large amount of expensive data gathering should be expected and while success rates might be higher than in the oil and gas exploration sector, delays and escalating costs are still likely to be significant with storage exploration. Costs are at-risk. • Storage exploration and appraisal data acquisition and study programs should be focused on reducing large geotechnical uncertainties (containment & sustained rate). • Acquiring data and conducting analyses which can quickly polarise the suitability or otherwise of a site are of highest appraisal value and may allow for a rapid reduction in the need for further exploration spending. It’s cheaper to seek data which “kills” an area! • It is essential to develop clear storage decision criteria, with both confidence levels and performance targets, which will define whether subsequent stages of (often larger) investment in plant should go ahead. You have to know when to stop!
  24. 24. Key Lessons Learned … #6 • When defining storage resources requirements it is essential to discuss the consequences and trade–offs between injection rate and/or cumulative volume objectives • Storage resources and field developments which match specific injection rate requirements are likely to be significantly different from (unrelated to) those which must only fulfill a cumulative volume target. • Appraisal of storage site and predictions of ‘reserves’ and performance must be based on long term, dynamic well testing (production or injection) and not on static–based derivations of capacity as is currently the case for most published estimates. Testing with CO2 is not technically necessary (at least not initially). • In addition to extended well tests, conceptual, engineered field development plans are essential and need to be constrained by real surface and environmental factors and potential sub–surface risk features. • Development drilling sequences need to be simulated to account for static and dynamic uncertainties and show how injection rate might be installed over time and might need to be maintained by in–fill drilling or venting or development of and transport to other sites.
  25. 25. Key Lessons Learned … #7 • High front–end (engineering) loading is needed for first–of–a–kind • Integrating CO2 separation technologies with power generation is not mature and there remain significant technical risks. Integration itself is not mature especially at location. • Proponents must recognise that these projects are technically complex and it is not just a matter of ‘integrating well understood, proven technologies’. Such statements understate the challenges (incl. local context) and set unreasonable stakeholder expectations for project development schedule and cost and, potentially, for plant start– up performance and availability. • Significant further technical development and engineering is required to provide confidence in plant design and performance (especially in an electricity market context). • Furthermore, if FOAK projects are to be economically viable then, notwithstanding currently immature ‘breakthrough developments’, significant developments in commercial terms and project financing as well as significant technical improvements will be required. • Funding arrangements must sustain an organisation through the project reviews and decision making processes and hiatuses that are inevitable between phases of a project.
  26. 26. Thanks and Acknowledgements ► This presentation is made possible through the willingness of the ZeroGen funding bodies to share lessons from the project. ► The ZeroGen funders were: ► the Queensland Government (DEEDI) ► Australian Coal Association (ACALET) ► the Australian Government (DRET). ► Continued funding of the role of CCS Director at UQ has been provided by ACALET Confidential
  27. 27. QUESTIONS / DISCUSSION Please submit your questions in English directly into the GoToWebinar control panel. The webinar will start shortly.
  28. 28. Please submit any feedback to: webinar@globalccsinstitute.com View the report: http://www.uq.edu.au/energy/docs/ZeroGen.pdf